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			REGIONAL PERFORMANCE North America In December 2002 we reached a significant milestone in North America when we achieved successful completion of our 3,890 MW US construction programme. Our overall capacity in North America now totals 4,415 MW (net). The 1,395 MW of new capacity added in 2002 constitutes the completion of the last three units at Hays in Texas (3 x 275 MW) and both units at Bellingham in New England (2 x 285 MW). Assets in operation Fuel Gross capacity MW power Net capacity MW power Gross capacity MW heat Net capacity MW heat Hartwell, Georgia, US Gas (OCGT) 310 155 – – Oyster Creek, Texas, US Gas (Cogen/CCGT) 425 210 100 50 Hays, Texas, US(1) Gas (CCGT) 1,100 1,100 – – Midlothian I and II, Texas, US(1) Gas (CCGT) 1,650 1,650 – – Blackstone, Massachusetts, US(1) Gas (CCGT) 570 570 – _ Milford, Massachusetts, US Gas (CCGT) 160 160 – – Bellingham, Massachusetts, US(1) Gas (CCGT) 570 570 – – North America total in operation 4,785 4,415 100 50 (1)Capacity shown for these assets is the nameplate capacity.   Gross turnover in North America increased to £315 million from £237 million in 2001 as new capacity was brought into commercial operation, but the impact was offset by weak wholesale pricing in our markets, particularly Texas. As a result of these lower prices our share of turnover from joint ventures decreased 22% to £60 million in 2002 from £77 million in 2001. Profit before interest and tax in the region increased to £99 million from £93 million, reflecting the addition of new capacity and continued compensation payments from Alstom (both the manufacturer of the gas turbines and the principal construction contractor). Compensation income from Alstom in 2002 was £102 million (£80 million in 2001), which relates to income lost during the year as a result of delays in the construction programme and consequent unavailability of plant, in addition to payments to compensate for reduced output and efficiency achieved in the year. Operating costs consist of both fixed operating costs, such as depreciation, payroll and property taxes, and variable operating costs, such as fuel. Our fixed cost base increased in line with the completion of the construction programme and variable costs tracked the profile of the physical output. We seek to minimise the impact of any potential increase in fuel prices, by locking in fuel supply at the same time that the output is contracted or sold. Operationally, all assets performed well. In particular, our focus has been the performance of the Alstom GT24B turbines. Although output and efficiencies remain below the contractual guarantee figures, the plants have demonstrated enhanced output, better heat rate and a significant improvement in their reliability and flexibility. Both of our key markets in the US, ERCOT (Texas) and NEPOOL (New England) exhibit summer peak demand, driven by air conditioning load. Accordingly, we focus attention on achieving high operational performance during this period. During the 2002 summer peak period, average availability of the GT24B turbine fleet was 95%. In terms of greenfield development, we made substantial progress during the year in developing our proposed 540 MW gas-fired Brookhaven project on Long Island in New York. In October 2002, following a 15-month public review, the project received final approval from the New York State Siting Board. We are currently negotiating commercial contracts to enable the financing of the project in the expectation that we can commence construction of this power plant during 2003. This strong operating performance, however, occurred in a very difficult market environment. The turmoil that followed the collapse of Enron led to a severe contraction in liquidity in the energy trading sector. This went hand in hand with a significant reduction in the number of creditworthy energy trading counterparties. This lack of liquidity in the market, combined with general overcapacity, and uncertainty created by the launch of new market designs for energy trading, had a negative impact on our key markets in the US (Texas and New England). The US merchant market is now characterised by a sharp reduction in new plant development and construction. However, we expect pricing to remain weak in our markets as the last of the current build programme becomes operational. The pace of recovery in 2004 and beyond will depend on the extent to which existing generators withdraw uneconomic plant, and we welcome the early evidence of this in Texas. In this regard the current high price of natural gas in the US further reduces the economic viability of much of the high heat rate incumbent plant. Our forward selling of output in the US is deliberately limited, as we do not lock in prices at this low level of the cycle. Where we see opportunities to add value and reduce risk, we forward contract, but we would need to see an improvement in forward prices before we significantly increase our contracted position. Europe and Middle East Gross turnover in Europe and Middle East decreased 16% to £440 million in 2002 from £521 million in 2001 reflecting the sale of Unión Fenósa Generacion (UFG) in mid 2001, partially offset by the acquisition of Rugeley (UK) at the same time. Assets in operation Fuel Gross Net Gross Net     capacity capacity capacity capacity     MW power MW power MW heat MW heat EOP, Czech Republic(1) Coal/Gas 585 580 2,040 2,020 Deeside, UK(2) Gas (CCGT) 500 500 – – Rugeley, UK Coal 1,000 1,000 – – Elcogas, Spain Gas (IGCC) 335 15 – – Pego, Portugal Coal 600 270 – – Marmara, Turkey Gas (CCGT) 480 160 - – Al Kamil, Oman Gas (OCGT 285 285 – – Europe and Middle East total in operation 3,785 2,810 2,040 2,020   Assets under construction Fuel Gross Net Gross Net     capacity capacity capacity capacity     MW power MW power desalination desalination         (MIGD) (MIGD) Shuweihat S1, UAE Gas (CCGT)/ desalination MIGD 1,500 300 100 20   (1)Gross capacity amount shown for EOP represents the actual net interest owned directly or indirectly by EOP. (2)Half the generating capacity at Deeside was mothballed in March 2002.   Profit before interest, tax and exceptional items decreased to £109 million from £141 million in 2001. This was principally due to a weak merchant market in the UK and the sale of our interest in UFG, and was exacerbated late in 2002 by the loss of the TXU tolling contract at Rugeley in the UK, and the collapse of the boiler house roof at EOP in the Czech Republic. Our cost profile in this region has undergone some significant changes, with Rugeley now responsible for the purchase of coal and the sale of power (functions previously undertaken by TXU Europe), and with the completion of our Al Kamil plant in Oman. All assets in this region delivered solid underlying operational performance with Pego, Deeside and Marmara all consistently achieving high levels of availability. In November 2002, we faced a major incident when the boiler house roof collapsed at one of EOP’s combined heat and power plants. No one was injured in this incident, but due to the extent of damage to the boilers, it did result in the loss of power and heat supply at a critical time in the year for our customers. Our engineers set themselves an aggressive restoration plan and delivered a remarkable performance by restoring full heating service within eleven days and returning the plant to full output just four weeks after the incident. We reported in December 2002 that as a result of TXU Europe Energy Trading Ltd entering administration, our tolling contract, which covered the full capacity of the Rugeley power station through to the end of 2005, was terminated. This triggered an entitlement to a termination payment and we continue to take all necessary steps to maximise recovery. While we feel that we are well positioned among creditors, we cannot yet accurately predict either the timing or the amount of such payments. In March 2002, as a consequence of uneconomic wholesale electricity prices in England and Wales, we mothballed half the capacity (250 MW) at Deeside. Additionally, due to uncertainty on the timing of recovery in electricity prices, we also wrote down the value of Deeside by £45 million at the half year. For the same underlying reasons, and as a result of the termination of the tolling contract, we have written down the value of Rugeley by £58 million at the year-end. In May 2002, construction commenced at the Shuweihat S1 power and water project (1,500 MW power, 100 MIGD water) site in Abu Dhabi. The construction programme continues to make good progress with more than six million man hours completed without a single Lost Time Accident. The primary power and water civil work is nearing completion, and the first of the five gas turbines has now been installed. The plant remains on course to start operation in the second half of 2004. Once operational, the power and water output from the facility will be sold to the Abu Dhabi Water and Electricity Company under a 20-year offtake agreement. In the second half of 2002, construction of our 285 MW Al Kamil power station in Oman was completed. The entire capacity at Al Kamil is contracted under a 15-year power purchase agreement with the Omani Ministry of Housing, Electricity and Water. Our Italian development programme continues with the dual objectives of securing fully permitted sites for the key projects, and of securing long-term offtake agreements. Progress has been slower than originally planned, principally driven by uncertainty on the design and implementation of the new market structure. We expect more clarity on this issue during 2003, and we remain focused on successfully delivering projects in Italy, which we continue to believe is an attractive long-term market for International Power. In Portugal, Tejo Energia (of which we own 45% and are the largest shareholder) is developing an 800 MW CCGT plant, which would be located adjacent to the existing coal-fired Pego plant in central Portugal. Although in its early stages, the project is progressing well. Following the submission of the Environmental Impact Study last year, the public enquiry stage expired in January 2003 without any comments from the public. As with all new build projects, we are committed to securing long-term offtake agreements and discussions have already commenced with potential counterparties. 2002 has been a tumultuous year for the electricity market in England and Wales with wholesale prices dropping to extraordinarily low levels, resulting in severe financial strain on wholesale generators. The primary cause for the low prices is general oversupply, worsened by tight liquidity following the exit of many energy traders from the market. However, at the end of 2002 prices did strengthen for a short period as a result of winter peak demand, coinciding with uncertainty in the market created by the well publicised distress of companies such as British Energy and TXU Europe. Almost one third of installed capacity is either for sale or in the hands of the lenders. The pace of recovery will largely depend on what happens to this generation capacity, but recovery is unlikely to occur in 2003. Apart from the UK, our highly contracted position, with proven offtakers, provides good visibility of earnings and cash-flow from the region. In line with our US trading strategy, we are forward selling our output from Deeside and Rugeley on a relatively short-term basis only. Australia Our performance in Australia illustrates the merits of a geographically diverse asset portfolio. Our forward contracted position at Hazelwood and Pelican Point, together with greater profitability at the Synergen peaking plants, led to enhanced financial performance in the region. Turnover in Australia increased by 16% to £226 million from £194 million in 2001. Profit before interest and tax was up 40% to £101 million from £72 million in 2001. Our average price achieved in Victoria was approximately A$41 per MW hour, up approximately 17% on 2001. As we own our fuel supply at Hazelwood (our largest plant in Australia), this translates directly into improved profitability. Assets in operation Fuel Gross capacity MW power Net capacity MW power Gross capacity MW heat Net capacity MW heat Hazelwood, Victoria Coal 1,600 1,470 – – Synergen, South Australia Various 360 360 – – Pelican Point, South Australia Gas (CCGT) 485 485 – – Australia total in operation 2,445 2,315 – –   Assets under construction SEAGas pipeline, 680 km       from Victoria to South Australia n/a n/a n/a n/a   During the year we made significant progress on the SEAGas pipeline project in which we have a 33% equity interest together with TXU Australia and Origin Energy. Construction of the pipeline from western Victoria to Adelaide is well underway with over 200 km of pipe now installed. This project not only helps to secure our future gas supplies at more competitive prices, but also represents an attractive investment in its own right. In May 2002 the project achieved financial close. The pipeline remains on track to start operation in the first quarter of 2004. In Australia we are benefiting from our forward contracted position and continue to be largely contracted for the remainder of 2003. Rest of World Gross turnover decreased to £148 million from £151 million in 2001. Profit before interest, tax and exceptional items increased to £108 million from £48 million last year. The principal driver behind this growth was the commencement of regular dividend receipts from Kot Addu Power Company (KAPCO) and Hub Power Company (HUBCO) in Pakistan. We continue to maintain close working relationships with the Water and Power Development Authority, our customer for both companies. Assets in operation Fuel Gross capacity MW power Net capacity MW power Gross capacity MW heat Net capacity MW heat HUBCO, Pakistan Fuel Oil 1,290 330 – – KAPCO, Pakistan Gas/Oil (CCGT) 1,600 575 – – Malakoff, Malaysia(1) Gas (OC/CCGT) 1,705 325 – – Shijiazhuang Yong Tai, PRC Coal(Cogen) 15 10 90 65 Pluak Daeng, Thailand Gas(Cogen) 110 110 20 20 Rest of World total in operation 4,720 1,350 110 85   (1)Gross capacity amount shown for Malakoff represents the actual net interest owned directly or indirectly by Malakoff.   At KAPCO, dividend payments of £42 million relating to the settlement of prior year receivables were treated as an exceptional item due to their non-recurring nature. All assets in this region delivered good operational performance. A highlight was our Pluak Daeng plant in Thailand that delivered robust financial and operational performance (98% availability) and also received ISO 14001 Environmental Management accreditation in 2002. In Malaysia, the ongoing 650 MW plant expansion at Malakoff’s Lumut site was completed in 2002. The final 230 MW of capacity commenced combined cycle operation in November, approximately three months ahead of schedule. Malakoff’s total installed capacity is now 1,705 MW (gross), all of which is contracted under long-term power purchase agreements with Tenaga Nasional Berhad. We have long-term power purchase agreements for each of our plants in this region and therefore financial performance is not subject to fluctuations in energy prices. OUTLOOK Two of our key merchant markets (US and UK) are at a low point in their cycles, with oversupply driving wholesale prices to uneconomic levels. Further removals of inefficient capacity are required to initiate any price recovery. There are indications that such removals of inefficient capacity will occur but not so quickly as to cause a significant improvement in power prices during 2003. We remain focused on operational excellence and fiscal discipline. With respect to 2003, based on consistent assumptions of no acquisitions, no significant price recovery in Texas, New England and the UK, recurring Pakistan revenue, and no currency translation effects, our earnings per share guidance remains in the range of 9p to 11p. CORPORATE The Group operates from a corporate office in London, and a small engineering office in Swindon, where corporate and business functions are based to support our worldwide operations. Continued control resulted in the cost of providing these services being contained at £29 million (2001: £28 million). In addition, the Group operates regional business support offices in the US, Australia, the Czech Republic, Spain, Italy, Japan and the UAE. These offices vary in size dependent on the scale of operations in the region, and apart from the US and Australia, are primarily focused on business development. Our US business has been supported from offices in Houston, Texas and Marlborough, Massachusetts. In 2002 it was decided to combine these activities in Marlborough and significant progress has been made in achieving this consolidation. The majority of the one-off costs associated with this consolidation were incurred in 2002 and should give rise to operational and cost efficiencies in future years. Exceptional items During the year the Group recorded the following three operating exceptional items: the write down of the Deeside plant by £45 million; the write down of the Rugeley plant by £58 million; the recognition of dividend income of £42 million from KAPCO in Pakistan that relates to the settlement of prior year receivables. The carrying values of our Deeside and Rugeley plants were reviewed following the sharp decline in both current and forward electricity prices in the UK. Deeside has been exposed to market prices since the offtake contract with Innogy terminated at the end of March 2002. As a response to these uneconomic wholesale prices, we mothballed half of the capacity (namely 250 MW) at that time. Rugeley, on the other hand, has only been exposed to market prices since late November 2002, when the tolling contract with TXU Europe, (covering 100% of the power offtake, and 100% of the fuel supply to December 2005) was terminated. This termination was a result of TXU Europe being placed in administration. The revised carrying values of the plants were determined by applying a risk adjusted discount rate of 8% to the post-tax cash flows expected from the plants over their remaining useful lives. A similar exercise was carried out on our US fleet following power price reductions in our principal US markets but this confirmed the current carrying value of this plant. KAPCO resumed the payment of dividends in 2002. Dividends in 2002 were boosted by the collection of receivables relating to earlier periods – collection was a direct result of the settlement of the dispute between KAPCO and the government offtaker in 2001. A gross dividend of £73 million was received in 2002 (the first since 1998), of which £42 million related to the settlement of prior period receivables and has accordingly been treated as exceptional because of its non-recurring nature. Net interest Net interest payable for the year ended 31 December 2002 was £132 million. Corporate and subsidiary operations accounted for interest payable of £97 million comprising gross interest of £126 million on bonds, bank loans and overdrafts offset by £24 million interest receivable and by capitalised interest of £5 million. Associated companies and joint ventures incurred net interest payable of £35 million. Consolidated interest cover was 2.9 times (excluding exceptional items), which is comfortably within all banking and credit rating covenants. FINANCIAL POSITION AND RESOURCES Liquidity A summary of the Group cash flow is set out below:   Year ended Year ended Nine months ended   31 December 31 December 31 December   2002 2001 2000   £m £m £m Operating profit (pre joint ventures and associates) – post exceptionals 105 163 59 Impairment of plant 103 – –   208 163 59 Depreciation and amortisation 112 95 40 Dividends from joint ventures and associates 84 59 21 Dividends received from fixed asset investments – ordinary 31 – – Movement in working capital and provisions (44) 16 (109) Operating cash flow 391 333 11 Capital expenditure – maintenance (48) (48) (36) Tax and interest paid (108) (106) (54) Exceptional items:   Dividends received from fixed asset investments 42 – –   Australian refinancing charges (25) – – Free cash flow 252 179 (79) Capital expenditure – growth (98) (358) (540) Acquisitions and disposals (144) 318 (42) National Power dividend – – (116) Foreign exchange, hedging and other 75 35 (33) Movement in net debt 85 174 (810) Opening net debt (897) (1,071) (261) Closing net debt (812) (897) (1,071)   Operating cash flow for the year ended 31 December 2002 increased by 17% to £391 million as compared to £333 million for the year ended 31 December 2001. The principal drivers include strong operating profit performance, an increase in dividend receipts from joint ventures and associates and the resumption of dividends from KAPCO. Capital expenditure on projects designed to maintain the operating capacity of our power stations was in line with the expenditure incurred in the previous year, reflecting the recurring and on-going nature of this expenditure. Capital expenditure to increase our operating capacity amounted to £98 million as compared to £358 million for the year ended 31 December 2001. This programmed reduction in our capital expenditure reflects the progressive completion of our new build capacity in Massachusetts and Texas. Net interest of £88 million (2001: £105 million) was paid in the year reflecting a small reduction in average debt levels over the course of the year, together with a slightly lower average cost of debt. Net tax payments in the year were £20 million (2001: £1 million). Acquisitions and disposals include a final payment of £133 million to TXU Europe in respect of the acquisition of our 1,000 MW Rugeley power station in the UK. Balance sheet A summarised, re-classified presentation of the Group balance sheet is set out below:   31 December 31 December 31 December   2002 2001 2000     (Restated) (Restated)   £m £m £m   Fixed assets   Intangibles and tangibles 2,474 2,643 2,209   Investments 507 509 818 Total fixed assets 2,981 3,152 3,027 Net current liabilities (excluding short term debt) (138) (320) (117) Provisions and creditors over one year (262) (238) (245) Net debt (812) (897) (1,071) Net assets 1,769 1,697 1,594 Gearing 46% 53% 67% Debt capitalisation 31% 35% 40%   Net assets at 31 December 2002 increased £72 million to £1,769 million, as compared to £1,697 million at the end of the previous year. This reflects the underlying profitability of the Group at £113 million, partially offset by £42 million reflecting the impact of foreign exchange (net of deferred tax) on the net investment in foreign entities and their related borrowings. Net debt at 31 December 2002 of £812 million is down from £897 million at 31 December 2001, reflecting the strong operating cash flow of the business and the positive impact of the translation of debt denominated in foreign currencies, which amounted to £98 million over the course of the year. Net debt at 31 December 2002 is shown net of facility fees of £27 million, which have been capitalised and offset against the debt in accordance with accounting standard FRS 4. Net debt and capital structure Group net debt at 31 December comprised:   2002 2001 2000   £m £m £m Cash and liquid investments 842 643 107 Euro dollar bonds (37) (41) (91) Convertible bond (231) (248) (235) Other loans – recourse – – (308) Loans – non-recourse (1,386) (1,251) (544)   (812) (897) (1,071)         The above net debt of £812 million excludes the Group’s share of joint ventures‘ and associates‘ debt of £503 million (2001: £487 million). These obligations are generally secured by the assets of the respective joint venture or associate borrower and are not guaranteed by International Power plc or any other Group company. In view of the significance of this amount, it has been disclosed separately. The Group has sufficient credit facilities in place to fund and adequately support its existing operations and to finance the purchase of new assets. These facilities comprise a revolving credit facility for US$540 million (expiry October 2004), a committed bilateral facility for US$30 million (expiry October 2004), a fixed rate Euro dollar bond of US$60 million (maturing December 2003) and a convertible bond for US$357 million (maturing November 2005 but with bondholders having the right to ‘put’ the bond back to the Group in November 2003). In addition, the Group has uncommitted bilateral credit lines from various banks at its disposal at the corporate level. Secured non recourse finance The Group’s financial strategy is to finance its assets by means of limited or non-recourse project financings at the asset or intermediate holding company level, wherever this is practical. As part of this strategy, it refinanced its Hazelwood Power plant in Australia in 2002, rolling over and significantly extending the maturity of the A$1.2 billion debt facility associated with this asset. In addition, the Group raised non-recourse facilities of £175 million to support the acquisition and operation of its 1,000 MW Rugeley plant acquired in 2001. At Rugeley, the fact that TXU Europe was placed into administration and thereby terminated our tolling contract, is in itself an event of default for our non-recourse term debt of £160 million. In the US, following a small number of refuted technical events of default, we are in discussions with our bank group. These claimed events of default principally relate to the availability of insurance cover for terrorism (which has now been obtained but was not generally available post 11 September 2001) and claimed failure to elect early completion of performance recovery periods. We believe we have constructive and acceptable plans in place to resolve all issues to the mutual benefit of both International Power and the banks. Until these issues are formally resolved and documented, the debt at Rugeley and American National Power (ANP) is reported as current non-recourse debt in our accounts. The maturity of thedebt will be redesignated when these discussions reach successful conclusion. In the US, our wholly owned subsidiary, ANP, has an investment grade credit rating. This rating is currently under review by Moody‘s who are expected to report in the near future. In line with all non-recourse finance, any support to either of these facilities would be entirely discretionary, and would not have a material impact on the Group’s liquidity or investment capability. Corporate and Group debt In December 2003 the US$60 million Euro dollar bond matures. We intend to meet this obligation through the use of cash resources, drawing down on bank lines or issuing new fixed rate debt depending on market conditions at the time. In November 2003, investors in our convertible bond have the right to ‘put’ the bond back to the Group. As the conversion exercise price is substantially above the present share price, it is likely that the bondholders will exercise this right. We are currently examining all our options to meet this obligation. We have more than sufficient liquid funds to meet this ‘put’, but we may issue a new instrument, amend the existing convertible bond or issue new fixed-rate debt depending on market conditions at the time. On 31 December 2002, we had aggregated debt financing of £1,654 million denominated principally in US dollars, Australian dollars, sterling, Thai bahts and Czech koruna. Of this amount, £1,078 million and £39 million is due for repayment within 2003 and 2004 respectively, with the majority of the remaining balance due after 2007. This short term debt includes the US and Rugeley debt. We believe we have constructive and acceptable plans to resolve all issues to the mutual benefit of both International Power and the banks such that a substantial portion of the £1,078 million will be redesignated as due in more than five years. At 31 December 2002, 77% of our borrowing was at fixed rates after taking account of interest rate swaps. The weighted average interest rate of the fixed rate debt was 6%. TREASURY AND COUNTERPARTY RISK POLICY Treasury policy seeks to ensure that adequate financial resources are available for the development of the Group’s business whilst managing its currency, interest rate and counterparty credit risks. The Group’s treasury policy is not to engage in speculative transactions. Group treasury acts within clearly defined guidelines that are approved by the Board. The major areas of treasury activity are set out below. Currency translation exposure In common with other international companies, the results of the Group’s foreign currency denominated operations are translated into sterling at the average exchange rates for the period concerned. The balance sheets of foreign operations are translated into sterling at the closing exchange rates. This translation has no impact on the cash flow of the Group. In order to hedge the net assets of foreign operations, borrowings are generally in the same currency as the underlying investment. The Group aims to hedge a reasonable proportion of its non-sterling assets in this way. For major currencies, it is our policy not to hedge currency translation through foreign exchange contracts or currency swaps. Average and year end sterling rates for major currencies which are significant to the Group were:       At 31   Average December   2002 2001 2002 2001           US dollar 1.50 1.44 1.61 1.46 Australian dollar 2.78 2.79 2.86 2.84 Euro 1.59 1.61 1.53 1.63 Czech koruna 49.16 54.94 48.42 52.57           Currency transaction exposure This arises where a business unit makes actual sales and purchases in a currency other than its functional currency. Transaction exposure also arises on the remittance from overseas of dividends or surplus funds. The Group’s policy is to match transaction exposure where possible, and hedge remaining transactions as soon as they are committed, by using foreign currency contracts and similar instruments. Short-term deposits Surplus funds are placed for short periods in investments that carry low credit risk and are readily realisable in major currencies. Interest rate risk The Group’s policy is to fix interest rates for a significant portion of the debt (77% as at 31 December 2002). Where project finance is utilised, our policy is to align the maturity of the debt with the contractual terms of the customer offtake agreement. Where appropriate, the Group will fix interest rates using forward rate or interest rate swap agreements. Significant interest rate management programmes and instruments require specific approval of the Board. Counterparty credit risk The Group’s policy is to manage its credit exposure to trading and financial counterparties within clearly defined limits. Energy trading activities are strictly monitored and controlled through delegated authorities and procedures, which include specific criteria for the management of counterparty credit exposures in each of our key regions. Counterparty exposure via customer offtake agreements is monitored and managed by the local asset team with assistance from Group treasury where appropriate. In addition, Group treasury manages the Group wide counterparty credit exposure on a consolidated basis, with the active and close involvement of the Global Risk Manager. Financial counterparty credit exposure is limited to relationship banks and commercial paper with strong investment grade credit ratings. CRITICAL ACCOUNTING POLICIES AND ESTIMATES We prepare our consolidated financial statements in accordance with accounting principles generally accepted in the UK. As such, we are required to make certain estimates, judgements and assumptions that we believe are reasonable based upon the information available. These estimates and assumptions affect the reported amounts of assets and liabilities at the date of the financial statements; the reported amounts of revenues and expenses during the periods presented and the related disclosure of contingent assets and liabilities. On an ongoing basis, we evaluate our estimates using historical experience, consultation with experts and other methods considered reasonable in the particular circumstances to ensure full compliance with UK GAAP and best practice. Actual results may differ significantly from our estimates, the effect of which is recognised in the period in which the facts that give rise to the revision become known. Our Group accounting policies are detailed on pages 55 to 56. The table opposite identifies the areas where significant judgements are required, normally due to the uncertainties involved in the application of certain accounting policies. Of the accounting policies identified in the table a discussion follows on the policies we believe to be the most critical in considering the impact of estimates and judgements on the Group’s financial position and results of operations. Accounting policy Judgements/uncertainties affecting application Consolidation policy – trade Determination of the extent of influence the Group investments, associates, joint has over the operations and strategic direction of ventures and subsidiaries entities in which it holds an equity stake. Liquidated damages Determination of the appropriate accounting treatment for receipts received from contractors. Fixed asset valuation Determination of trigger events indicating impairment and measurement of fair value using projected cash flows, together with risk adjusted discount rates, or other more appropriate methods of valuation. Determination of useful lives and residual value of assets. Exceptional items Determination of the transactions which require separate disclosure as exceptional items. Tax provisions Determination of appropriate provisions for taxation, taking into account anticipated decisions of tax authorities. Assessment of our ability to utilise tax benefits through future earnings.     Consolidation policy – significant influence The determination of the level of influence the Group has over a business is often a mix of contractually defined and subjective factors that can be critical to the appropriate accounting treatment of entities in the consolidated accounts. We achieve influence through Board representation and by obtaining rights of veto over significant actions. We generally treat investments where the Group holds less than 20% of the equity as trade investments. Trade investments are carried in the balance sheet at cost less amounts written off. Income is recorded as earned on the receipt of dividends from the investment. Where the Group owns between 20% and 50% of the equity and has significant influence over the entity’s operating and financial policies, we generally treat the entity as an associated undertaking or joint venture. Equally, where the Group holds a substantial interest (but less than 20%) in an entity and is able to exert significant influence over its operations, we treat it as an associated undertaking or joint venture. Conversely, although we generally treat a holding of more than 20% of the equity as an associated undertaking or joint venture, where the Group is unable to exert significant influence over the operations of the entity, we treat it as a trade investment. Associated undertakings and joint ventures are accounted for using the equity method of accounting, which involves including the Group’s share of operating profit, interest and tax on the respective lines of the profit and loss account, and the Group‘s share of net assets within the fixed asset investments caption in the balance sheet. In addition, we provide voluntary disclosure of the amount of net debt held by these entities, although in accordance with UK GAAP, this net debt is not included in the consolidated balance sheet. The Group generally consolidates entities in which it holds in excess of 50% of the equity and where it exerts control over the strategic direction of the entity. However, if the Group were to hold in excess of 50% of the equity but was unable to exert significant influence over the strategic direction or operations of the entity, we would account for the entity as an associated undertaking or joint venture. Liquidated damages The Group receives amounts from contractors in respect of the late commissioning and under performance of new power plants. The receipts that relate to compensation for lost revenue are treated as revenue when the compensation is due and payable by the contractor. Those receipts that relate to compensation for plants not achieving long-term performance levels specified in the original contracts are recorded as a reduction in the cost of the assets. Fixed asset valuation Tangible fixed assets The original cost of greenfield-developed assets includes relevant borrowing and development costs: Interest on borrowings relating to major capital projects with long periods of development is capitalised during construction and written-off as part of the total cost over the useful life of the asset. Project development costs (including appropriate direct internal costs) are capitalised from the point that the Board confirms that it is reasonably certain that the project will proceed to completion. Depreciation of plants is charged so as to write down the assets to their residual value over their estimated useful lives. Gas turbines and related equipment are depreciated over 30 years to a 10% residual value, unless the circumstances of the project or life of specific components indicate a shorter period or a lower residual value. Coal plant is considered on an individual basis. Tangible fixed assets and fixed asset investments Management regularly considers whether there are any indications of impairments of the carrying values of fixed assets or investments (e.g. the impact of current adverse market conditions). Impairment reviews are generally based on risk adjusted discounted future cash flow projections that inevitably require estimates of discount rates and future market prices over the remaining lives of the assets. Exceptional items Under UK GAAP, an item is considered exceptional if it derives from ordinary activities and is considered of such significance that separate disclosure is needed if the financial statements are to give a true and fair view. All exceptional items, other than those listed below are included under the statutory line-item to which they relate. In addition, separate disclosure on the face of the profit and loss account is required for the following items: Profits or losses in the sale or termination of an operation. Costs of a fundamental re-organisation or restructuring having a material effect on the nature and focus of the Company’s operations. Profits or losses on the disposal of fixed assets. The determination of the transactions which are considered to be exceptional in nature is often a subjective matter.